Wellbores are formed in subterranean formations for various purposes including, for example, extraction of oil and gas from the subterranean formation and extraction of geothermal heat from the subterranean formation. Wellbores may be formed in a subterranean formation using a drill bit such as, for example, an earth-boring rotary drill bit. Different types of earth-boring rotary drill bits are known in the art including, for example, fixed-cutter bits (which are often referred to in the art as “drag” bits), rolling-cutter bits (which are often referred to in the art as “rock” bits), diamond-impregnated bits, and hybrid bits (which may include, for example, both fixed cutters and rolling cutters). The drill bit is rotated and advanced into the subterranean formation. As the drill bit rotates, the cutters or abrasive structures thereof cut, crush, shear, and/or abrade away the formation material to form the wellbore. A diameter of the wellbore drilled by the drill bit may be defined by the cutting structures disposed at the largest outer diameter of the drill bit.
The drill bit is coupled, either directly or indirectly, to an end of what is referred to in the art as a “drill string,” which comprises a series of elongated tubular segments connected end-to-end and extends into the wellbore from the surface of the formation. Various tools and components, including the drill bit, may be coupled together at the distal end of the drill string at the bottom of the wellbore being drilled. This assembly of tools and components is referred to in the art as a “bottom hole assembly” (BHA).
The drill bit may be rotated within the wellbore by rotating the drill string at the rig floor from the surface, or the drill bit may be rotated by coupling the drill bit to a downhole motor, which is also coupled to the drill string and disposed proximate the bottom of the wellbore. The downhole motor may comprise, for example, a hydraulic Moineau-type motor having a shaft, to which the drill bit is mounted, that may be caused to rotate by pumping fluid (e.g., drilling mud or fluid) from the surface down through the center of the drill string, through the hydraulic motor, out from nozzles in the drill bit, and back up to the surface of the formation through the annular space between the outer surface of the drill string and the exposed surface of the formation within the wellbore.
It is known in the art to use what are referred to as “reamer” devices (also referred to in the art as “hole-opening devices” or “hole openers”) in conjunction with a drill bit as part of a bottom hole assembly when drilling a wellbore in a subterranean formation. In such a configuration, the drill bit operates as a “pilot” bit to form a pilot bore in the subterranean formation. As the drill bit and bottom hole assembly advance into the formation, the reamer device follows the drill bit through the pilot bore and enlarges the diameter of, or “reams,” the pilot bore.
The bodies of earth-boring tools, such as drill bits and reamers, are often provided with fluid courses, such as “junk slots,” to allow drilling mud (which may include drilling fluid and formation cuttings generated by the tools that are entrained within the fluid) to pass upwardly around the bodies of the tools into the annular shaped space within the wellbore above the tools outside the drill string.
Some earth-boring rotary drill bits are inherently aggressive and may undesirably damage wellbore components (e.g., surface casing, risers, other tubular members, etc.) with which the earth-boring rotary drill bit inadvertently comes into contact. In addition, some earth-boring rotary drill bits suffer from instability and bit whirl and related vibrations that may damage the bottom hole assembly (BHA) and reduce a cutting efficiency of the earth-boring rotary drill bit.